Electrolyzed water—amine compositions and methods of use

ABSTRACT

The invention is directed to a treatment fluid comprising electrolyzed water and an amine, and methods for producing and using same in the treatment of a gas or liquid containing a contaminant such as an acid gas or a sulphur compound.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. ProvisionalApplication No. 61/438,835 filed on Feb. 2, 2011, entitled “Compositionand Method for Scavenging Sulphur Compounds”, the contents of which areincorporated herein by reference.

FIELD OF THE INVENTION

The present invention is directed to a treatment fluid comprisingelectrolyzed water and an amine, and methods for producing and usingsame in the treatment of a fluid containing a contaminant such as anacid gas or a sulphur compound.

BACKGROUND OF THE INVENTION

In upstream oil and gas operations, hydrocarbon liquids and gases aretypically produced with some contaminants, such as acid gases andsulphur compounds. Acid gases are gases which form acidic solutions whenmixed with water, and typically comprise hydrogen sulphide and carbondioxide. Hydrogen sulphide is a colorless, flammable, poisonous gas,having a characteristic foul odor of rotten eggs. It may be producedfrom the bacterial breakdown of organic proteinaceous matter from plantsor animals, or by contact at high temperatures between elemental sulphuror certain sulphur-containing compounds and organic materials. Hydrogensulphide may also be formed as an undesirable byproduct in variousindustrial processes such as, for example, the production of coke fromsulphur-containing coal; the refining of sulphur-containing crude oils;the production of disulphide; the manufacture of viscose rayon; and theKraft process for conversion of wood into wood pulp.

Hydrogen sulphide may also be a byproduct of wastewater from treatmentplants or water from agricultural practices. Unpleasant odors fromliquids used in janitorial processes, RV holding tanks, portable toiletsand the like are typically attributed to hydrogen sulphide. Such foulodors may be eliminated if the emission of hydrogen sulphide could becontrolled in some manner.

Natural gas or crude oil having high concentrations of hydrogen sulphideare known as “sour gas” and “sour crude” respectively. Hydrogen sulphidein sour gas and crude oil streams is separated during gas sweeteningprocesses, such as the widely used amine process which requires asolution of water and a chemical amine to remove carbon dioxide andseveral sulphur compounds.

Since hydrogen sulphide is toxic, it represents a significant threat topublic safety and health, and has potential to cause serious healthrisks in the oil and gas, livestock, waste management, and janitorialindustries. At 200 ppm, hydrogen sulphide is undetectable by smell, anda concentration greater than 200 ppm induces nausea and headaches. At500 to 1000 ppm, hydrogen sulphide leads to unconsciousness, with deathresulting within two to twenty minutes unless the victim is removedimmediately from exposure.

Other contaminants of natural gas or crude oil include sulphur compoundssuch as mercaptans.

There is thus a need for a simple, economical and effective means ofremoving contaminants such as acid gases or sulphur compounds fromhydrocarbons or other gases or liquids.

SUMMARY OF THE INVENTION

The present invention is directed to a treatment fluid comprisingelectrolyzed water and an amine, and methods for producing and usingsame in the treatment of a hydrocarbon gas or liquid containingcontaminants.

In one aspect, the invention comprises a treatment fluid for treating agas or a liquid containing an acid gas therein, comprising electrolyzedwater in an amount between about 20% to about 80% by volume based on thetotal volume of the treatment fluid, and an amine in an amount betweenabout 20% to about 80% by volume based on the total volume of thetreatment fluid.

In one embodiment, electrolyzed water is present in an amount of about50% by volume based on the total volume of the treatment fluid. In oneembodiment, the amine is present in an amount of about 50% by volumebased on the total volume of the treatment fluid. In one embodiment, theamine comprises monoethanolamine.

In one embodiment, the pH of the treatment fluid is in a range aboveabout pH 12.0. In one embodiment, the pH of the treatment fluid isbetween about pH 12.6 and 13.3.

In one embodiment, the treatment fluid is prepared by (a) mixingelectrolyzed water and amine to form a mixture; (b) stirring themixture; and (c) allowing the mixture to cool.

In one embodiment, the treatment fluid further comprises an alcohol,such as methanol, and/or a salt, such as potassium chloride solution.

In another aspect, the invention comprises a method for treating a gasor a liquid containing a contaminant, comprising the step of contactingthe gas or the liquid with a treatment fluid as described herein,resulting in a decrease in the amount of the contaminant. The method maybe practiced in a vessel or chamber. In one embodiment, the inventioncomprises an in-situ method of treatment by injection of the treatmentfluid into a wellbore or a subterranean formation.

In one embodiment, the gas or liquid comprises natural gas, sour gas,sour crude oil, sour water, or mixtures thereof. In one embodiment, thecontaminant comprises an acid gas, or a sulphur compound such ashydrogen sulphide, carbonyl sulphide, or a mercaptan. In one embodiment,the mercaptan comprises methyl mercaptan, ethyl mercaptan, n-propylmercaptan, or iso-butyl mercaptan.

Additional aspects and advantages of the present invention will beapparent in view of the description, which follows. It should beunderstood, however, that the detailed description and the specificexamples, while indicating preferred embodiments of the invention, aregiven by way of illustration only, since various changes andmodifications within the spirit and scope of the invention will becomeapparent to those skilled in the art from this detailed description.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention is directed to a treatment fluid comprisingelectrolyzed water and an amine, and methods for producing and usingsame in the treatment of a gas or liquid. When describing the presentinvention, all terms not defined herein have their common art-recognizedmeanings.

In one embodiment, the invention provides a treatment fluid for treatinga gas or a liquid containing a contaminant comprising an acid gas or asulphur compound therein, comprising electrolyzed water in an amountbetween about 20% to about 80% by volume based on the total volume ofthe treatment fluid, and an amine in an amount between about 20% toabout 80% by volume based on the total volume of the treatment fluid.

In one embodiment, the invention provides a method for treating a gas ora liquid containing a contaminant comprising an acid gas or sulphurcompound, comprising the step of contacting the gas or the liquid withthe treatment fluid of the present invention, resulting in a decrease inthe amount of the contaminant.

In one embodiment, the invention provides an in situ method for treatinga gas or a liquid containing a contaminant comprising an acid gas or asulphur compound therein produced from a well, comprising the step ofinjecting the treatment fluid of the present invention into the well ora subterranean formation so as to contact the gas or the liquid,resulting in a decrease in the amount of the contaminant.

Electrolyzed water is also known as electro-activated water orelectro-chemically activated water solution. It is produced by theelectrolysis of ordinary water containing dissolved sodium or potassiumchloride. In one embodiment, the concentration of the sodium chloride isin the range of between about 10 ppm to about 50 ppm, and in a preferredembodiment, the concentration of the sodium chloride is about 35 ppm. Asused herein, “anolyte” means an aqueous solution produced at the anodeby the electrolysis of aqueous solutions of sodium or potassiumchloride. The anolyte produced comprises free available chlorine,primarily in the form of sodium hypochlorite. In one embodiment, theanolyte comprises greater than about 4000 ppm of free chlorine. Theamount of free chlorine in a sample of anolyte is known to slowlydecrease over time. “Catholyte” is the aqueous solution which isproduced at the cathode.

As used herein, “electrolyzed water” means any aqueous solution whichcontains free available chlorine resulting from the electrolysis ofwater having dissolved chloride ions. It may include anolyte, or anolytewhich has been mixed with catholyte.

To prepare the treatment fluid of the present invention, suitablesolutions of anolyte may be produced by an electrolysis reactor, such asthat described, for example, in U.S. Pat. No. 4,875,988 to Aragon,issued Oct. 24, 1989; U.S. Pat. No. 5,540,819 to Bakhir et al., issuedJul. 30, 1996; U.S. Pat. No. 5,628,888 to Bakhir et al., issued May 13,1997; and co-pending U.S. patent application Ser. No. 12/962,385 toStorey and Arrison, filed Dec. 7, 2010 (the contents of which areincorporated herein by reference). If the anode and cathode compartmentsare separated by a semi-permeable membrane, the composition of theanolyte and catholyte may be quite different. Typically, the anolyte ispH neutral or slightly acidic, while catholyte is basic due to theproduction of sodium hydroxide.

Without restriction to a theory, it is believed that anolyte does notcontain chlorite (ClO₂ ⁻) and chlorate (ClO₃ ⁻) ions. The free availablechlorine in anolyte exists primarily as hypochlorous acid (HClO) orhypochlorite ions (ClO⁻), free chlorine (Cl₂) and chloride ion (Cl).Without restriction to a theory, it is believed that hypochlorous acidand hypochlorite ions, free chlorine, and/or chloride ions, arerestricted or limited in crossing the ionomeric semi-permeable membrane.As a result, they accumulate in the anolyte to very high levels.

In one embodiment, the anolyte is combined with the catholyte (primarilysodium hydroxide) produced at the cathode in the electrolytic process.The resulting solution still maintains a high concentration of freeavailable chlorine and may have a pH of about 8.3. Without restrictionto a theory, it is believed that the majority of the free availablechlorine exists as NaHClO (sodium hypochlorite). In one embodiment, theconcentration of free available chlorine is greater than about 1000 ppmin the electrolyzed water, preferably greater than about 2000 ppm, andmore preferably greater than about 3000 ppm. The concentrationmay be ashigh as about 4400 ppm.

Amines may be produced through well known chemical syntheses, and arereadily commercially available. As used herein, “amine” means an organiccompound with one or more of the hydrogen atoms in ammonia replaced byorganic groups. The term includes the three classes of amines dependenton the number of hydrogen atoms replaced, namely primary, secondary andtertiary amines. The organic groups can include aliphatic, alicyclic oraromatic groups. Examples of amines include, but are not limited to,monoethanolamine, methylamine, ethylamine, diethylamine, trimethylamine,aniline, benzylamine, and the like. In one embodiment, the aminecomprises monoethanolamine.

The treatment fluid of the present invention is prepared by combiningelectrolyzed water with an amine solution to form a mixture. In oneembodiment, exothermic reactions occur upon mixing, and the mixture isleft to cool before use. Preparation of the treatment fluid shouldpreferably be conducted in a well-ventilated area, due to thepossibility of chlorine gas production. In one embodiment, the pH of thetreatment fluid is in a range of about pH 12.0 or higher and may be inthe range of about 12.6 to about 13.3. In one embodiment, the mixturedoes not have any free available chlorine. Without restriction to atheory, it is believed that the free available chlorine in theelectrolyzed water is released as chlorine gas upon mixing with theamine.

It will be appreciated by those skilled in the art that the proportionsof the individual components may be varied to optimize the contaminantremoval effect produced by the treatment fluid to suit the specific gasor liquid being treated. In one embodiment, the proportion of theelectrolyzed water to the amine solution is in an amount between about20% to about 80% by volume based on the total volume of the treatmentfluid. In a preferred embodiment, the electrolyzed water is present inan amount of about 50% by volume based on the total volume of thetreatment fluid. In one embodiment, amine is present in an amountbetween about 20% to about 80% by volume based on the total volume ofthe treatment fluid, and in a preferred embodiment, is present in anamount of about 50% by volume based on the total volume of the treatmentfluid.

The treatment fluid may be used as mixed, or may be diluted in water, anaqueous salt solution, or an alcohol, or mixtures thereof. In oneembodiment, the treatment fluid may be used diluted in water as a 2%(v:v) solution, with good hydrogen sulphide removal activity. In anotherembodiment, the treatment fluid is miscible and may be mixed withmethanol prior to use. In another embodiment, the treatment fluid may bemixed with a potassium chloride solution to increase the density of thetreatment fluid when used downhole.

Once prepared, the treatment fluid may be evaluated to ensure scavengingactivity by testing one or more samples of different gases and liquidsknown to contain acid gases or sulphur compounds. Non-limiting examplesof such gases and liquids include natural gas, sour gas, sour crude oil,sour water, or mixtures thereof. As used herein, “natural gas” means amixture of hydrocarbon gases which occurs with petroleum deposits,principally methane together with varying quantities of ethane, propane,butane, and other gases, and impurities including hydrogen sulphide andcarbon dioxide. “Sour gas” means natural gas comprising gases which areacidic either alone or when associated with water. The term includesacid gases associated with oil and gas drilling and production such as,for example, hydrogen sulfide and carbon dioxide. “Sour water” meanswaste waters containing fetid materials comprising sulfur compounds.

As used herein, “sulphur compound” means a substance consisting of twoor more elements in union, with at least one element being sulphur. Thesulphur compound may be selected from hydrogen sulphide, carbonylsulphide or a mercaptan including, but not limited to, methyl mercaptan,ethyl mercaptan, n-propyl mercaptan and iso-butyl mercaptan.

It will be recognized by those skilled in the art that there are varioussuitable methods for measuring hydrogen sulfide in environmental samplesincluding, but not limited to, gas chromatography with flame photometricdetection, gas chromatography with electrochemical detection, iodometricmethods, the methylene blue colorimetric or spectrophotometric method,the spot method using paper or tiles impregnated with lead acetate ormercuric chloride, ion chromatography with conductivity, potentiometrictitration with a sulfide ion-selective electrode, atomic absorptionspectroscopy, and the like. Sulphur compounds such as mercaptans have acharacteristic disagreeable sulphurous odor, even in very lowconcentrations. The absence of such odors, while not conclusive, isevidence that sulphur compounds are not present.

Gases and liquids containing sulphur compounds or carbon dioxide maythus be treated by contacting the gases or liquids with the treatmentfluid of the present invention, resulting in a decrease in the amount ofthe acid gases or sulphur compounds. As demonstrated in Examples 2-7,the composition decreased the amount of hydrogen sulphide in sour gas(Example 2), sour crude oil (Examples 3-5 and 8), sour water (Examples6-7) and in situ mixtures of gas, sour crude oil and sour water(Examples 9-10). The magnitude of the decrease in such amounts appearsto be dependent upon the duration of treatment. In Examples 3-5, theamount of hydrogen sulphide decreased within one hour of treatment.Within twenty-four hours, no hydrogen sulphide was detected. Withoutrestriction to a theory, it is believed that the treatment fluid of thepresent invention scavenges sulphur compounds, hydrogen sulphide orcarbon dioxide within gases or liquids. In one embodiment, the gas orthe liquid is treated for at least one hour. In one embodiment, the gasor the liquid is treated for between about two to about three hours. Inone embodiment, the gas or the liquid is treated for about twenty-fourhours.

The treatment may comprise any method of contacting the gas or liquidwith the treatment fluid, such as bubbling gases through a liquid, oragitation of a mixture within a closed container. Suitable methods andapparatuses are well known to those skilled in the art of sweeteningsour gas and sour crude streams.

Without restriction to a theory, it is believed that the electrolyzedwater-amine composition may also have a germicidal effect onmicroorganisms which can generate hydrogen sulphide such asDesulfovibrio species, and other sulphate-reducing bacteria.Accordingly, when used in situ, such as by injection into a wellbore ora producing formation, the treatment fluid may have the dual effect ofneutralizing acid gases, and also killing the microorganisms that may beproducing hydrogen sulphide.

Exemplary embodiments of the present invention are described in thefollowing Examples, which are set forth to aid in the understanding ofthe invention, and should not be construed to limit in any way the scopeof the invention as defined in the claims which follow thereafter.

Example 1 Preparation of Electrolyzed Water-Amine Composition

The anolyte-amine treatment fluid used in Examples below was prepared bymixing equal volumes of electrolyzed water (4,400 ppm free availablechlorine) made by combining equal volumes of anolyte and catholyte, withliquid monoethanolamine, with stirring. The mixture heated up uponmixing, and was allowed to cool to room temperature before use.

Example 2 Treatment of Gas with Electrolyzed Water-Amine Composition

Gas having a total volume of 198,000 ft³ and a concentration of 4,000ppm of hydrogen sulphide was treated by flushing the gas at a flow rateof 12,000 ft³/min through a column containing 1 m³ of water with a 2%(v:v) solution of the electrolyzed water-amine treatment fluid for twohours and forty-five minutes. The exit stream did not contain anyhydrogen sulphide. The test was repeated, with the total volume of gasbeing 216,000 ft³ and treatment for three hours. The exit stream did notcontain any hydrogen sulphide. No sulphurous odor was detected.

Example 3 Treatment of Sour Crude Oil with Electrolyzed Water-AmineComposition

Three jars containing 500 mL of sour crude oil having 16,000 ppm ofhydrogen sulphide were treated with 10 and 20 mL of the electrolyzedwater-amine treatment fluid. The concentration (ppm) of hydrogensulphide remaining after various timepoints is summarized in Table 1:

TABLE 1 Anolyte-amine H₂S at time 0 H₂S at 1 hour H₂S at 24 hourscomposition (ppm) (ppm) (ppm) (mL) 16,000 30 0 10 16,000 15 0 10 16,0008 0 20

Example 4 Treatment of Sour Crude Oil with Electrolyzed Water-AmineComposition

Three jars containing 500 mL of sour crude oil having 5,000 ppm ofhydrogen sulphide were treated with 5, 10, and 20 mL of theanolyte-amine treatment fluid. No sulphurous odor was detected after 24hours. The concentration (ppm) of hydrogen sulphide remaining aftervarious timepoints is summarized in Table 2:

TABLE 2 electrolyzed water- H₂S at time 0 H₂S at 2 hours H₂S at 24 hoursamine composition (ppm) (ppm) (ppm) (mL) 5,000 25 0 5 5,000 10 0 105,000 20 0 20

Example 5 Treatment of Sour Crude Oil with Electrolyzed Water-AmineComposition

Two jars containing 500 mL of sour crude oil having 6,000 ppm ofhydrogen sulphide were treated with 5 and 10 mL of the anolyte-aminetreatment fluid. No sulphurous odor was detected after 24 hours. Theconcentration (ppm) of hydrogen sulphide remaining after varioustimepoints is summarized in Table 3:

TABLE 3 electrolyzed water- H₂S at time 0 H₂S at 1 hour H₂S at 24 hoursamine composition (ppm) (ppm) (ppm) (mL) 6,000 20 0 5 6,000 10 0 10

Example 6 Treatment of Sour Water with Electrolyzed Water-AmineComposition

Two jars containing 500 mL of sour water having 35,000 ppm of hydrogensulphide were treated with 1 mL of the electrolyzed water-aminetreatment fluid. The concentration (ppm) of hydrogen sulphide remainingafter various timepoints is summarized in Table 4:

TABLE 4 Anolyte- H₂S at time 0 H₂S at 1 hour H₂S at 24 hours aminecomposition (ppm) (ppm) (ppm) (mL) 35,000 2,000 2,000 1

Example 7 Treatment of Waste Sour Water with Electrolyzed Water-AmineComposition

A truck tank initially contained 13,510 liters of waste sour waterhaving 35,000 ppm of hydrogen sulphide. Twenty liters of theelectrolyzed water-amine treatment fluid were added. After thirty-sevenminutes, the concentration of hydrogen sulphide of the sour water haddecreased to 1,400 ppm.

Example 8 Treatment of Sour Crude Oil with Electrolyzed Water-AmineComposition in Methanol Solution

Approximately 125 mL of electrolyzed water-amine treatment fluid wasmixed with 125 mL of methanol to produce a homogeneous solution. Thesolution was allowed to rest for 24 hours, over which time theelectrolyzed water-amine treatment fluid remained miscible within themethanol.

Ten milliliters of the methanol mixture solution was added to acontainer containing 500 mL of a sour crude oil sample initially having200 ppm of hydrogen sulphide. The mixture was shaken every five to tenminutes over a one-hour period. The concentration of hydrogen sulphidewas measured as zero parts per million.

Example 9 Treatment of Sour Crude Oil, Sour Gas and Sour Water MixtureIn Situ in Well with Electrolyzed Water-Amine Composition in PotassiumChloride Solution

A well produced 75 barrels of oil per day, 100 barrels of water per dayand 90,000 cubic feet of natural gas per day. The well casing mixturecontained 1,800 ppm of hydrogen sulphide. The well was swabbed todetermine which one of its five producing zones was sour. The sour zonewas isolated by plug means.

Approximately 55 US gallons of electrolyzed water-amine treatment fluidwas mixed with 130 barrels of a 2 percent potassium chloride solution.The mixture was pushed into the sour zone. For the next 1.5 days, thehydrogen sulphide concentration in the oil well casing mixture reducedto 0 to 100 ppm. After three days of production, the hydrogen sulphideconcentration in the oil well casing mixture increased back to 1,800ppm.

Example 10 Treatment of Sour Crude Oil, Sour Gas and Sour Water MixtureIn Situ

Electrolyzed water-amine treatment fluid was directly injected into thecasing of the well described in Example 9, at a rate of 13.5 US gallonsper day. The hydrogen sulphide concentration in the production mixturereduced from 1,800 ppm to 400 ppm. When the produced stream was pumpedinto a storage tank and tested after 24 hours residence time, there wasno detectable hydrogen sulphide.

REFERENCES

The following references are incorporated herein by reference (wherepermitted) as if reproduced in their entirety. All references areindicative of the level of skill of those skilled in the art to whichthis invention pertains.

-   Aragon, P. J. Electrolytic cell. U.S. Pat. No. 4,875,988, issued    Oct. 24, 1989.-   Bakhir, V. M.; Vedenkov, V. G.; Leonov, B. I.; Prilutsky, V. I.;    Repetin, E. A.; Zadorozhny, J. G.; Naida, N. N.; Mashkov, O. A.;    Dzheiranishvili, N. V. and Butin, S. K. Water treatment method. U.S.    Pat. No. 5,540,819, issued Jul. 30, 1996.-   Bakhir, V. M.; Zadorozhny, J. G. and Barabash, T. Apparatus for    electrochemical treatment of water and/or water solutions. U.S. Pat.    No. 5,628,888, issued May 13, 1997.-   Storey, W. D. and Arrison, N. L. Microcidal composition. U.S. patent    application Ser. No. 12/962,385, filed Dec. 7, 2010.

What is claimed is:
 1. A treatment fluid for treating a gas or a liquidcomprising a contaminant comprising an acid gas or a sulphur compound,comprising reaction products of electrolyzed water and monoethanolamine.2. The treatment fluid of claim 1, produced by mixing electrolyzed waterin an amount between about 20% to about 80% by volume andmonoethanolamine in an amount between about 20% to about 80% by volumebased on the total volume of the treatment fluid.
 3. The treatment fluidof claim 2, produced by mixing electrolyzed water and monoethanolaminein about equal volumes.
 4. The treatment fluid of claim 1, 2 or 3wherein the electrolyzed water comprises anolyte and catholyte.
 5. Thetreatment fluid of claim 2 wherein the pH of the treatment fluid isabove about pH 12.0.
 6. The treatment fluid of claim 5, wherein the pHof the treatment fluid is between about 12.6 to about 13.3.
 7. Thetreatment fluid of claim 1 further comprising methanol or a dissolvedsalt.
 8. The treatment fluid of claim 1 wherein the electrolyzed watercomprises greater than about 4000 ppm of free available chlorine priorto mixing with monoethanolamine.
 9. The treatment fluid of claim 2 or 8which comprises substantially no free available chlorine.
 10. A methodfor treating a gas or a liquid containing a contaminant comprising anacid gas or a sulphur compound therein, comprising the step ofcontacting the gas or the liquid with the treatment fluid of claim 1.11. The method of claim 10, wherein the acid gas comprises hydrogensulphide, or carbon dioxide.
 12. The method of claim 10 wherein thesulphur compound comprises carbonyl sulfide, or a mercaptan.
 13. Themethod of claim 12, wherein the mercaptan comprises methyl mercaptan,ethyl mercaptan, n-propyl mercaptan, or iso-butyl mercaptan.
 14. Themethod of claim 10, wherein the gas or liquid is natural gas, sour crudeoil, sour gas, sour water, or a mixture thereof.
 15. The method of claim10 wherein the gas or liquid containing a contaminant is in a wellbore,or a subterranean formation intersected by a wellbore, and the treatmentfluid of claim 1 is injected into the wellbore.
 16. An in situ methodfor treating a gas or a liquid containing a contaminant comprising anacid gas or a sulphur compound therein produced by a well, comprisingthe step of injecting the treatment fluid of claim 1 into the well so asto contact the gas or the liquid, wherein a decrease in the amount ofthe contaminant is effected.